Wear Data Quantification for Well Tools

ABSTRACT

A method of quantifying wear data on a well tool includes identifying the well tool based on a solid model file and a data file corresponding to the well tool, wherein the solid model and data files are stored on a computer system and separately identify wear parts of the well tool, scanning the well tool with a scanner and thereby generating a scanned file of the well tool, the scanner being in communication with the computer system, aligning the scanned file with the solid model file to obtain an overlay output, creating digital features on the wear parts of the scanned file, and calculating deviation between the solid model file and the scanned file at the digital features for the wear parts and thereby determining material removed from the wear parts of the well tool.

BACKGROUND

In the oil and gas industry, several types of well tools are useddownhole to perform various wellbore operations. Drill bits, forexample, are commonly run downhole two or three (or more) times to drilla wellbore or extend its length. When a drill bit is new, itsperformance and drilling capability are fairly predictable and generallyfollow manufacturer specifications. In later stages, however, and due touncertain operating and formation conditions, the drill bit willgradually wear and degrade into what is commonly referred to as a “dull”bit. Dull bits can slow the rate of wellbore penetration, thus requiringthe drilling operator to apply more weight on bit, which, in turn,accelerates drill bit wear. Dull bits also often experience unbalancedside forces, which lead to whirl, vibration, and instability duringoperation. Consequently, when a drill bit becomes dull, it is commonlyremoved from operation and either scrapped or refurbished for subsequentuse.

Determining whether a bit is scrapped or refurbished is typically basedupon internal guidelines established by individual bit companies andexperienced personnel within those companies. In addition to makingdeterminations on repairability of dull bits, it is critical to documentwear sustained on dull drill bits. The International Association ofDrill Contractors (IADC) bit dull grading system was developed toprovide a standardized protocol for evaluating drill bits to classifydrill bit wear/damage and reason pulled. In the IADC dull gradingprocess, a skilled evaluator visually inspects the dull bit and manuallyquantifies the observed wear using a standardized eight-field code withassociated descriptors. The dull grading process, however, is atime-consuming process that is highly subjective, rarely repeatable, andoften inaccurate.

Thus, what is needed is an improved method of determining andquantifying drill bit wear, which can lead to improved bit materialselection, design optimization, and performance.

BRIEF DESCRIPTION OF THE DRAWINGS

The following figures are included to illustrate certain aspects of thepresent disclosure, and should not be viewed as exclusive embodiments.The subject matter disclosed is capable of considerable modifications,alterations, combinations, and equivalents in form and function, withoutdeparting from the scope of this disclosure.

FIG. 1 is an isometric view of an example well tool that may incorporatethe principles of the present disclosure.

FIG. 2 is a schematic diagram of an example scanning system that mayincorporate the principles of the present disclosure.

FIG. 3 is a process flow diagram of an example method of determining andquantifying wear data on a well tool, according to one or moreembodiments.

FIG. 4 depicts example solid model and scanned file outputs to whichmanual point pair alignment has been undertaken, according to one ormore embodiments.

FIGS. 5A and 5B depict example digital features applied to specific wearparts of the drill bit of FIG. 1, according to one or more embodiments.

FIGS. 6A and 6B depict enlarged images of an example cutting elementdemonstrating area point cloud measurements, according to one or moreembodiments.

FIGS. 7A-7D are example wear data reports that may be generated using anauto-generate report programming instruction, according to one or moreembodiments.

FIG. 8 is an enlarged scanned view of a worn cutter seated within acorresponding cutter pocket, according to one or more embodiments.

FIG. 9A is an isometric view of an example cutting element after havingsustained failure damage and depicting an extracted surface featurecreated based on the surface of the failure plane.

FIG. 9B is a graphical representation of missing portions of the cuttingelement of FIG. 9A.

FIG. 10 depicts an example of computational fluid dynamics flow linesacross a drill bit being correlated to cutting element wear, accordingto one or more embodiments.

FIG. 11 is a schematic diagram of the computer system of FIG. 2.

DETAILED DESCRIPTION

The present disclosure is related to analyzing well tools and, moreparticularly, to scanning used well tools with three-dimensional ortwo-dimensional imaging systems and subsequently quantifying wear data.

Embodiments of the present disclosure describe methods of analyzing welltools to determine and quantify wear data. According to methodsdisclosed herein, a used well tool is scanned and the resulting scannedfile is aligned with and compared with a solid model (e.g., CAD model)of the well tool in its as-designed state. Material loss can then bemeasured directly for analysis by subtracting the scanned parts from thecorresponding solid model parts. One issue with conventional scanning ofwell tools is that the scan data is commonly represented as a singlesurface geometry that lacks any distinction between individual, discretecomponents of the well tool. Because the individual components are notdiscrete 3D solids in conventional scanning techniques, they cannot beeasily measured.

Assemblies made up of various parts subject to wear are of interest indefining the amount of wear experienced during operation of theassembly. The presently described methods facilitate measurement ofdiscrete volumetric and/or area wear of components and parts of welltools. The methods disclosed herein provide improved consistency,granularity (i.e., characterization), and accuracy of wear data asfeedback for application specific well tool selection, designoptimization, and material selection. In some cases, formationcharacteristics can be correlated to wear identified on well toolcutting elements, thus enabling indexing of formation abrasion, thermaland/or impact severity and probability.

Moreover, the wear or wear rate of specific materials in the well toolscan be tracked over time to ensure there is no drifting of performancedue to changes in materials and/or manufacturing. Wear and wear rate canalso be tracked to better understand variations in lithology and/ordrilling parameters of subterranean formations. Furthermore, the methodsdescribed herein may help enhance a manufacturer's ability to performeconomic analysis and make material selections for well tools based on arate of return from a performance perspective. Thus, the methodsdiscussed herein provide quick and reliable feedback to manufacturers,operators, and tool companies to aid in optimization of drillingefficiency and economics.

FIG. 1 is an isometric view of an example well tool 100 that mayincorporate the principles of the present disclosure. In the illustratedembodiment, the well tool 100 comprises a rotary drill bit, but theprinciples of the present disclosure are equally applicable to otherwell tools commonly used in the oil and gas industry and correspondingto a wide variety of oilfield equipment (both surface and subsurface),well drilling equipment, well drilling tools, well completion equipment,well completion tools, well service tools, well service equipment,and/or associated components. Other examples of the well tool 100include, but are not limited to, bit bodies associated with rotary drillbits, fixed cutter drill bits (e.g., PDC bits), drill stringstabilizers, roller cone drill bits, cones for roller cone drill bits,rotary steering tools (e.g., directional tools), logging while drillingtools, measurement while drilling tools, side wall coring tools,underreamers, fishing spears, washover tools, whipstocks, productionpacker components, float equipment, casing shoes (e.g., a casing shoewith cutting structures), well screens, gas lift mandrels, downholetractors, tool joints, rotors, stator and/or housings for downholemotors, blades and/or housings for downhole turbines, latches fordownhole tools, and other downhole tools associated with drilling andcompleting a wellbore.

In the present discussion, the well tool 100 will be described withreference to the rotary drill bit depicted in FIG. 1. Consequently, thewell tool 100 will alternatively be referred to herein as the “drill bit100” or the “rotary drill bit 100”. The term “rotary drill bit” refersto various types of fixed cutter drill bits, drag bits, matrix drillbits, steel body drill bits, roller cone drill bits, rotary cone drillbits, and rock bits operable to form a wellbore. As will be appreciated,rotary drill bits and associated components incorporating the teachingsof the present disclosure may have many different designs,configurations, and/or dimensions.

As illustrated, the drill bit 100 includes a generally cylindrical bitbody 102 that provides or otherwise defines one or more drill bit blades104 separated by junk slots 106. The blades 104 may be provided in awide variety of configurations including, but not limited to,substantially arched, helical, spiraling, tapered, converging,diverging, symmetrical, asymmetrical, or any combination thereof. In theillustrated embodiment, some of the blades 104 extend to a centerline108 of the bit body 102 and may be referred to as “primary” blades,while other blades 104, referred to as “secondary” blades, do not extendto the centerline 108 and operate to “follow” the primary blades 104during operation.

The bit body 102 can be formed integrally with the blades 104, such asbeing milled out of a steel blank. Alternatively, the blades 104 can bewelded to the bit body 102. In other embodiments, the bit body 102 andthe blades 104 may be formed of a matrix material (e.g., tungstencarbide matrix with an alloy binder) sintered and/or cast in a mold of adesired shape, with the blades 104 also being integrally formed of thematrix with the bit body 102.

The drill bit 100 further includes a plurality of cutting elements 110(alternately referred to as “cutters”) fixed to the blades 104. In somecases, some of the cutting elements 110 may be mounted at the leadingface of some or all of the blades 104. Each cutting element 110 may bereceived within and bonded to a dedicated cutter pocket machined or castinto the bit body 102 at the corresponding blade 104. One or more of thecutting elements 110 may include a cutting table or face bonded to asubstrate secured within a corresponding cutter pocket. The cuttingtable may be made of a variety of hard or ultra-hard materials such as,but not limited to, polycrystalline diamond (PCD), sintered tungstencarbide, thermally stable polycrystalline (TSP), polycrystalline boronnitride, cubic boron nitride, natural or synthetic diamond, hardenedsteel, or any combination thereof. The substrate may also be made of ahard material, such as tungsten carbide or a ceramic. In otherembodiments, however, one or more of the cutting elements 110 may notinclude a cutting table. In such embodiments, the cutting elements 110may comprise sintered tungsten carbide inserts without a cutting tableand bonded to corresponding cutter pockets. The cutting elements 110 maybe bonded to the corresponding blade 104 such that they are fixed oralternately allowed to rotate.

The cutting elements 110 may comprise any suitable cutter designed tocut, gouge, and/or scrape into underlying rock formations as the bitbody 102 rotates during downhole operation. The cutting elements 110 caninclude primary cutting elements, back-up cutting elements, secondarycutting elements, or any combination thereof. In some applications,other types of cutting elements may be fixed to various portions of theprimary or secondary blades 104. Such cutting elements can include, butare not limited to, cutters, compacts (e.g., polycrystalline diamondcompacts or “PDC”s), buttons, inserts, and gage cutters suitable for usewith a wide variety of drill bits. In some cases, the blades 104 mayalso include one or more depth of cut controllers (DOCCs) configured tocontrol the depth of cut of the cutting elements 110. Various featuresmay also be affixed to the blades 104 to mitigate vibration.

Moreover, the drill bit 100 may further include one or more gauge pads112 provided on outer radial portions of the blades 104 to contactradially adjacent portions of the drilled wellbore. The gauge pads 112operate to provide added stability and protection to gauge cuttingelements (if any) while maintaining a predetermined diameter of thedrilled wellbore. The gauge pads 112 may also contain one or morecutting elements in order to enhance the ability of the well tool tomaintain a properly gauged well bore.

The drill bit 100 further includes a pin 114 that defines AmericanPetroleum Institute (API) drill pipe threads used to releasably engagethe drill bit 100 with drill pipe or a bottom-hole assembly (BHA)whereby the drill bit 100 may be rotated relative to the centerline 108.In example operation, as the drill bit 100 advances into the earth, adrilling fluid (e.g., water, drilling mud, etc.) is communicated to oneor more nozzles 116 provided in the bit body 102 to cool and lubricatethe drill bit 100. The drilling fluid is discharged from the nozzles 116and into the junk slots 106, and a mixture of drilling fluid, formationcuttings, and other downhole debris flow through the junk slots 106 tobe returned to the well surface via the annulus of the drilled wellbore.

Operation of the drill bit 100 in downhole environments inevitablycauses wear and tear on the drill bit 100, which gradually decreases itsefficiency and effectiveness. Eventually the decreased drillingefficiency of the drill bit 100 outweighs the drilling interests and thedrill bit 100 must be returned to the surface and replaced orrefurbished.

As indicated above, dull bits are either scrapped or refurbished forsubsequent use and, in some cases, this determination is reached by askilled evaluator. Because the dull grading process is time-consuming,highly subjective, and often inaccurate, other wear analysis techniqueshave been developed to provide more efficient means of wear dataquantification. For example, worn well tools, such as drill bits, can bedigitally scanned to obtain and process three-dimensional (3D) images ofthe worn well tools that help manufacturers determine whether a wornwell tool should be scrapped or refurbished. Moreover, metrologysoftware has been developed to calculate wear by comparing separatemodels, but conventional scanning techniques quantify wear (i.e.,deviation) for a body as a whole, and are not designed to distinguishwear/deviation for separate, distinct parts or components within onescanned image. More specifically, conventional methods of scanning welltools to determine material loss (volumetric and/or area) typicallygenerate scan data represented as a single, monolithic surface geometrythat lacks any distinction between the individual, discrete components(parts) of the well tool. Because the individual components are notdiscrete 3D solids, they cannot be measured independently but only aspart of the whole. It is believed that no solution has previously beendisclosed that automates material loss/wear calculations for individual,discrete wear parts or components of a well tool.

According to the present disclosure, when evaluating the wear state andcharacteristics of a well tool, such as the drill bit 100, wear islinked and/or correlated to specific regions or “wear parts” of the welltool. As used herein, the term “wear parts” refers to parts, components,or regions of a well tool that have a higher susceptibility to wear andtear during operation as compared to other parts, components, or regionsof the well tool. Wear parts on the drill bit 100, for example, includeat least the blades 104, the cutting elements 110, and the gauge pads112 due to the significant variation of forces applied to theseindividual regions across the bit profile. In some embodiments, wearparts can also include depth of cut controllers (DOCCs), if present.Additionally, these separate regions of the bit profile experiencevarious forms and severity of impact loading/instability, performvarying degrees of work, travel at varying speeds, and travel highlyvariable distances.

The methods described herein automate the process of scanning a wornwell tool, selecting wear parts of interest on a three dimensional solidmodel of the well tool generated by means of computer-aided design (CAD)software, aligning the solid and scanned models of the well tool, andcalculating the deviation (wear) between the scanned part and the solidmodel part, thus providing a user (e.g., an operator, a tool company,etc.) with the material loss (volumetric and/or area) at the wear partsof interest. As will be appreciated, the methods described herein may beadvantageous over the time-consuming and subjective manual process ofanalyzing dull drill bits. Whereas manually analyzing a dull drill bitcan require several hours of manual labor, the methods disclosed hereincan be accomplished in just minutes.

FIG. 2 is a schematic diagram of an example scanning system 200 that mayincorporate the principles of the present disclosure. The scanningsystem 200 (hereafter “the system 200”) may be configured to scan a welltool, such as the drill bit 100. As illustrated, the scanning system 200includes a scanner 202 and a computer system 204 in communication withthe scanner 202. In some embodiments, the computer system 204 mayinclude two or more computers (e.g., multi-pc workflow) networkedtogether or otherwise capable of communicating one with the other.Having more than one computer may be advantageous in increasing capacity(e.g., maximizing number of well tools scanned without delay due toinspection) while creating real-time/simultaneous inspections uponcompletion of a scan. In such embodiments, for example, the computersystem 204 may include a scanning computer separate from an inspectioncomputer, among other computer devices.

The scanner 202 may be positioned to obtain scanned images of the drillbit 100, which may be positioned on a stand 206. In some embodiments,the scanner 202 may be designed to obtain three-dimensional (3D) imagesof the drill bit 100 and may thus comprise a type of 3D scanner or 3Dscanning system. For purposes of this disclosure, the term “3D scanner”or “3D scanning system” refers to any assembly by which distance datamay be collected or calculated and reconstructed to extrapolate theshape of an object (e.g., a well tool). Such assemblies may refer to anykind of 3D scanning system, including contact or non-contact 3Dscanners, such as a time-of-flight 3D laser scanner, a triangulation 3Dscanner, a structured light 3D scanner, an optical 3D scanner,stereoscopic scanners, general photography devices, or any combinationthereof. Further, in one or more embodiments, the 3D scanning system maybe an internal component of an electronic device or a separate externalcomponent connected to an electronic device operable at will by a user.

In other embodiments, however, the scanner 200 may be designed to obtainhigh-resolution two-dimensional (2D) images of the drill bit 100,without departing from the scope of the disclosure. In such embodiments,the scanner 200 may comprise a high-resolution camera or the likecapable of obtaining high-resolution 2D photographic (still) imagesand/or video. Moreover, in such embodiments, the computer system 204 maybe programmed or otherwise configured to implement photogrammetrytechniques to gather measurements and data about the well tool byanalyzing the change in position from two or more different images.Accordingly, the principles of the present disclosure are equallyapplicable to 2D scanning operations.

In some embodiments, the scanner 202 may be mounted to a supportassembly 208 capable of moving the scanner 202 about the drill bit 100to capture scanned images (3D or 2D) of all exterior portions of thedrill bit 100. The support assembly 208 may include, for example, one ormore robotic arms and/or lifts that may help maneuver and position thescanner 202 at all required angles and locations relative to the drillbit 100. In some embodiments, the support assembly 208 may be automated,but may alternatively be manually operated. In some embodiments, thescanner 202 may remain stationary and the stand 206 may alternatively berotatable and/or movable up and down to help enable adequate scanning ofthe drill bit 100. In yet other embodiments, the scanner 202 maycomprise a hand-held scanning system and a user or operator may hold thescanner 202 and walk around the periphery of the drill bit 100 whiledigitally “painting” the drill bit 100 with the scanner 202 to obtainthe necessary scanned images (3D or 2D).

In some embodiments, the drill bit 100 may be prepared for scanning,such as by applying reflective markers to assist in stitching the 3Dscan together, applying matting spray to remove reflective glare, andthe like. The scanner 202 may be designed to operate with an accuracy ofapproximately 0.0005-0.003 inches or better.

The scanner 202 may communicate with the computer system 204 via anyknown wired or wireless means. In at least one embodiment, the computersystem 204 may comprise one component of a larger computer network. Thecomputer system 204 may include a processor and a non-transitory,computer readable medium (i.e., a memory) programmed withcomputer-executable instructions that, when executed by the processor,perform the methods described herein. More particularly, the computersystem 204 may have 3D modeling and metrology software stored thereon,which may include instructions to receive and process images captured bythe scanner 202 and generate a 3D image of the drill bit 100 based onthe captured images.

The 3D image of the drill bit 100 may comprise a scanned “mesh” file(e.g., .stl, point cloud, IGES, STEP, etc.) comprising a complex polygonmesh structure corresponding to the scanned dimensions andconfigurations of the drill bit 100 as obtained by the scanner 202. Asdescribed in more detail below, the scanned file of the drill bit 100may be compared against a solid model (e.g., a computer-aided design orCAD solid model) file of the drill bit 100 corresponding to the originalmanufacturer specifications for the drill bit 100. The scanned file maybe spatially aligned with the corresponding solid model file and anydeviation between individual scanned parts (regions) and thecorresponding solid model parts may be indicative of how much wear thedrill bit 100 experienced during operation. Such comparisons may be usedto quantify, often in a digital format, specific amounts of abrasion,erosion, and/or wear of associated blades 104 (FIG. 1), cutting elements110 (FIG. 1), and/or gauge pads 112 (FIG. 1), for example.

FIG. 3 is a process flow diagram of an example method 300 of determiningand quantifying wear data on a well tool, according to one or moreembodiments. The method 300 will be discussed with respect todetermining and quantifying wear data of the drill bit 100 of FIGS. 1-2,but it will be appreciated that the method 300 may alternatively be usedto determine and quantify wear data of any of the well tools orassociated components mentioned herein. Moreover, the method 300 mayalso incorporate and use the scanner 202 (FIG. 2) and the computersystem 204 (FIG. 2) described herein to help determine and quantify thewear data.

As illustrated, the method 300 may first include identifying a well toolfor wear data analysis, as at 302. The well tool must be properlyidentified in order to be able to run the software programminginstructions that facilitate automated wear data quantification. In thisstep, the dull drill bit 100 (or any other well tool mentioned herein)may be identified by the computer system 204 (FIG. 2) based on originaldesign and preparation files used to manufacture the drill bit 100. Thedesign and preparation files can include, but are not limited to, solidmodels (e.g., CAD files) and data files (e.g., comma separated variableor “CSV” files) corresponding to the drill bit 100, and may be preparedbased on tool features such as part number, outer diameter, cutter size,blade count, etc. In at least one embodiment, the data file could beprogrammatically generated based on the embedded parts and detailsprovide in the solid model file. More specifically, an operator may beable to merely input a part number or the like and the computer system204 may be configured to pull the necessary data file information fromthe solid model file. In such embodiments, the information for the datafile may be embedded within the solid model file or otherwise within thebit manufacturer's bit design database.

Both the solid model and data files will be separable into common wearparts of the drill bit 100, such as the blades 104 (FIG. 1), the cuttingelements 110 (FIG. 1), and the gauge pads 112 (FIG. 1). This separabledata will be required to enable the computer system 204 to run the weardata quantification programming instructions (e.g., macros) describedherein and obtain wear data quantification for individual (discrete)wear parts, as opposed to a volumetric material loss for the drill bitas a whole, or performing manual procedures to quantify wear.

The solid model file may be saved in the computer system 204 (FIG. 2)such that the common wear parts of the drill bit 100 are separatelyidentified but embedded in a main assembly file. Accordingly, the mainassembly file is comprised of the bit body 102 (FIG. 1) along with thewear parts and any other discrete parts or components that are cast,welded, or otherwise attached to the bit body 102.

Similarly, the data file may be saved in the computer system 204 (FIG.2) with separate wear parts of the drill bit 100 being separatelyidentifiable, as is common to data files. More specifically, the datafile may include various part parameters related to the drill bit 100,such as bit size, bit description, scale CAD factor, the CAD part namefor each cutting element 110 (FIG. 1), a list of cutting element 110numbers (as assigned in the main assembly CAD file), the CAD part namefor each blade 104 (FIG. 1), the corresponding blade 104 number for eachcutting element 110, the nominal area/volume value for each cuttingelement 110, wear tolerances (if applicable/desired), nominal gaugediameter for the bit body 102 (FIG. 1), DOCC elements, and features ofany DOCC elements.

In the event some of the cutting elements 110 comprise shaped(non-cylindrical) cutters, which exhibit a different nominal value thantraditional cylindrical cutters, the data file may include (indicate)the appropriate nominal value for each cutting element 110. In someembodiments, for example, shaped and cylindrical cutting elements 110may be used in an alternating layout along the blades 104 (FIG. 1) basedon the radial position of the cutters on the profile. In suchembodiments, the appropriate nominal area value may be applied to thevarying cutter geometries to ensure accurate area/volume wearmeasurements, which would otherwise be erroneous if only one nominalvalue were applied to all cutting elements 110.

The well tool may then be properly situated in preparation for scanning,as at 304. The drill bit 100, for example, may be positioned on thestand 206 (FIG. 2) adjacent the scanner 202 (FIG. 2). In someembodiments, properly situating the drill bit 100 on the stand 206 mayentail aligning one of the blades 104 (FIG. 1) with a predeterminedangular orientation or coordinate (e.g., 270°). Such alignment may proveadvantageous in enabling operators (e.g., scanner operators) to automatesubsequent scanning processes with drill bits having the same partnumber. In other embodiments, a fixturing apparatus could be used tofacilitate consistent alignment of the well tool when situating the welltool on a stand for scanning. In this scenario, the fixturing would alsobe modelled with the well tool to aid in alignment. In yet otherembodiments, a datum feature could be designed into the well tool toallow for a datum-based alignment process.

Various tool data corresponding to the drill bit 100 may then beuploaded to the computer system 204 (FIG. 2) by the user to enable thecomputer system 204 to subsequently relate a scanned file of the drillbit 100 with the design and preparation CAD and data files. Example tooldata that may be uploaded include, for instance, the part number, theserial number, and operation information for the drill bit 100. Theoperation information refers to where the drill bit 100 was used(commissioned), and such information may be subsequently correlated tothe wear data. In some embodiments, the tool data corresponding to thedrill bit 100 may be manually uploaded to the computer system 204. Inother embodiments, however, the tool data may be obtained and uploadedelectronically, such as by scanning a barcode corresponding to thespecific drill bit 100, which will automatically upload thecorresponding tool data from a database or data file, or both.

The well tool may then be scanned, as at 306. As indicated above, thescanner 202 (FIG. 2) may be operated to obtain multiple scanned images(3D or 2D) of the drill bit 100 from all angles and covering allexterior surfaces of the drill bit 100. These images may be subsequentlytransmitted to the computer system 204 (FIG. 2) for processing andgeneration of a scanned file corresponding to the drill bit 100, as at308.

Once the scan of the well tool is complete, the computer system 204 maybe programmed to run a first or “data import and preparation”programming instruction. In some embodiments, the 3D modeling andmetrology software stored on the computer system 204 is automaticallyopened upon scan completion, and the 3D modeling and metrology softwaremay be programmed to run the data import and preparation programminginstruction. The data import and preparation programming instructioninstructs the computer system 204 to import the 3D images obtained bythe scanner 202 (FIG. 2) and generates the scanned file from the 3Dimages. As provided above, the scanned file consists of a 3D modelcomprising a complex polygon mesh structure corresponding to the scanneddimensions and configurations of the drill bit 100.

The data import and preparation programming instruction also instructsthe computer system 204 to load the applicable design and preparationfiles corresponding to the drill bit 100. More specifically, the solidmodel files related to the drill bit 100 are loaded based on the tooldata entered by the user prior to scanning the drill bit 100; e.g., thepart number, the serial number, etc. of the drill bit 100. Moreover, thesolid model files may be organized and renamed based on the dialoguetree of the data (e.g., CSV) files corresponding to the drill bit 100.This may be advantageous in organizing the cutting elements 110 (FIG. 1)by blade 104 (FIG. 1) and relative cutter position for subsequentfeature generation, wear calculations, and reporting. In someapplications, the dialogue tree includes the main assembly CAD modelexpanded with a view of the embedded parts of the well tool. Thedialogue tree can include native naming and organization of otherembedded parts that make up the main assembly. For example, the cuttingelements 110 (FIG. 1) can be designated in the dialogue tree for wearcalculations in an updated organization and naming sequence tofacilitate preferred reporting. In at least one embodiment, the dialoguetree includes branch names, object names (including measurements, colormaps, etc.), index numbers, and icons.

The method 300 may further include aligning the scanned file of the welltool with the solid model file corresponding to the well tool to obtainan overlay or “mated” output, as at 310. In some embodiments, properlyaligning the scanned file with the solid model file may comprise threeor more alignment steps or stages that may be performed to ensure properalignment for the subsequent programming instructions that will be runto accurately record wear data. In the first alignment step, the dataimport and preparation programming instruction may prompt the user toundertake a manual point pair alignment between the scanned file and thecorresponding solid model file, as at 312. Manual point pair alignmentmay be used to generally align the scanned file with the solid modelfile, and helps positively locate and identify wear parts of interest inthe drill bit 100, such as each cutting element 110 (FIG. 1), each blade104 (FIG. 1), and each gauge pad 112 (FIG. 1). This can be done bymarking particular surfaces or parts on the solid model file with aunique identifier, and then making a corresponding mark on the samesurfaces or parts of interest provided by the scanned file.

Referring briefly to FIG. 4, illustrated is an example solid model fileoutput 402 and an example scanned file output 404 on which manual pointpair alignment has been undertaken, according to one or moreembodiments. As illustrated, several particular surfaces and parts ofthe drill bit 100 have been manually (e.g., electronically via acomputer) marked by the user on the solid model file output 402 withunique identifiers 406. Corresponding marks in similar locations havealso been manually placed on the scanned file output 404 with the sameunique identifiers 406 to indicate the same surfaces and parts ofinterest, thus linking the solid model file to the scanned file.Consequently, the cutting elements 110 included in the solid model filewill be aligned with the corresponding cutting elements 110 provided inthe scanned file, the blades 104 included in the solid model file willbe aligned with the corresponding blades 104 provided in the scannedfile, and the gauge pads 112 included in the solid model file will bealigned with the corresponding gauge pads 112 provided in the scannedfile.

The result of the manual point pair alignment is an overlay (mated)output 408 of the CAD and scanned files, which provides a roughalignment of the two file outputs 402, 404. In some embodiments, themanual point pair alignment may require 5 to 20 or more uniqueidentifiers 406 to be placed on both the solid model file output 402 andthe scanned file output 404 to achieve the rough alignment. In at leastone embodiment, the manual point pair alignment step 312 mayalternatively be automated by using datums and cutter position files.

Referring again to FIG. 3, in one or more embodiments, the manual pointpair alignment of step 312 may be required only for new (unknown or notpreviously scanned) well tools with new (unknown) part numbers. Forexample, when a subsequent drill bit having the same part number as thedrill bit 100 is scanned, the data import and preparation programminginstruction may be configured to automate the point pair alignment forthe subsequent drill bit since its features and design will be the sameas the previously scanned and aligned drill bit 100. Automating thepoint pair alignment for additional well tools with same part numbersmay be possible, however, only if the well tools are properly situated(oriented) and aligned for scanning, as discussed above in step 304.

Once the point pair alignment occurs, a second alignment step may ensueto globally align the scanned file with the solid model file, as at 314.More specifically, the data import and preparation programminginstruction may then trigger a global alignment performed within the 3Dmodeling and metrology software that takes the rough point pairalignment and transforms it to a tighter alignment. In this process, abest-fit global alignment is created between all surfaces of the scannedmesh and solid model file outputs 402, 404 (FIG. 4), which provides amore accurate alignment between the scanned mesh and solid model files.In this process, all surfaces of the well tool may be utilized toachieve a best-fit alignment.

In some embodiments, a third alignment step may then be undertaken toperform a local alignment of individual wear parts of the well toolrequiring wear calculations, as at 316. The third alignment step takesinto consideration shrinkage in manufacturing processes of cast bitsthat may cause the scanned file to deviate from the solid model filebased on manufacturing deviations or tolerances. More specifically, thisstep is designed to remove inconsistencies in positioning of the wearparts between the solid model and scanned files that result fromshrinkage and/or deviations inherent in any manufacturing processes.This is accomplished by performing alignments on the individual wearcomponents on an individual basis, thus eliminating the bit body and anypositioning inconsistencies. Without this step, if a given wear partwere out of position by even a small degree, the point clouds would notrepresent the wear part but rather the region surrounding the wear part.

In some embodiments, step 316 may alternatively be accomplished using alocal best fit to critical feature alignment method. The local best fitto critical feature alignment may be undertaken to improve local cutteralignment if a substantial portion of the tungsten carbide substrate orcutting/diamond table are worn or missing. For instance, if the tungstencarbide substrate on the back portion of the cutter has suffered severeerosion, the alignment step could be skewed because so much of thefeature is missing. An improved alignment could be performed by aligningonly “critical features” of the cutter that did not sustain wear. Inthis example, this may entail using the cutting/diamond table only foralignment purposes. As will be appreciated, the inverse could be appliedif the cutting/diamond tables are substantially worn or missing. Thelocal best fit to critical feature alignment method may be done manuallyby an operator, or the process may be automated using the computersystem 204.

In some embodiments, the data import and preparation programminginstruction in the third alignment step 316 may be programmed to providelocal alignment of each cutting element 110 (FIGS. 1 and 4) and cuttercylinder of the scanned file with the corresponding portions of the 3Dfile. This step reduces the alignment process to only cutter surfacessince without accurate local cutter-to-cutter alignment, the resultingwear data would be erroneous. As a result, each cutting element 110 isaligned on a one-by-one basis for optimal alignment, and regardless ofdeviations present between the scanned mesh and solid model files.

Once the alignment sequence(s) is/are complete, as at 310, the method300 may then proceed to create features on wear parts of the scannedfile requiring wear calculations, as at 318. More specifically, oncealignment is complete and the overlay output 408 (FIG. 4) is generated,the computer system 204 may be programmed to run a second or “createdimensions” programming instruction, which may be programmed into the 3Dmodeling and metrology software. The create dimensions programminginstruction may be configured to create and place digital features onspecific wear parts of the overlay output 408 of the drill bit 100 thatwill undergo wear calculations.

Referring to FIG. 5A, in some embodiments, a digital feature in the formof a digital plane 502 may be created and aligned with the cutter faceof each cutting element 110 of the drill bit 100, and based on valuesobtained from the data file corresponding to the drill bit 100. Asillustrated, the digital plane 502 may comprise a circle, an ellipse, orany other geometric shape sufficient to align with the correspondingcutter face of each cutting element 110.

Referring to FIG. 5B, in other embodiments, or in addition thereto, adigital feature in the form of a digital cylinder 504 may be created andaligned with the gauge pads 112 of the drill bit 100. More specifically,the digital cylinder 504 may be created based on the manufactureddiameter of the drill bit 100, as obtained from the corresponding datafile, or as extracted/measured from the CAD model. The digital cylinder504 may help determine the gauge diameter measurement when undertakingwear calculations, thus helping determine the true (actual) gauge of thedrill bit 100 after it exits the wellbore. This may help quantify theamount of material removed, and may also help specify if the gauge pads112 are out of tolerance, if at all, and by what amount.

Referring again to FIG. 3, the method 300 may further includecalculating the deviation between the solid model file and the scannedfile at each wear part and thereby determining material removed from thewear parts of the well tool, as at 320. Once all the digital featureshave been created, the computer system 204 may be programmed to run athird or “volume/area calculation” programming instruction, which may beprogrammed into the 3D modeling and metrology software. The volume/areacalculation programming instruction may be configured to retrievenominal values that were set for the cutter dimensions (e.g., areaand/or volume) of each cutting element (FIGS. 1, 4, and 5A) and theouter diameter of the bit body 102 (FIG. 1) at the gauge pads 112 (FIGS.1, 4, and 5B). Such nominal values may be retrieved from the data fileor CAD dimensions corresponding to the drill bit 100. The volume/areacalculation programming instruction may then be programmed to comparethe nominal values to the scanned file to quantify the area or volumeremoved from the wear parts, or wear scar distance at the wear parts. Insome embodiments, the diamond area removed (DAR) from the cuttingelements 110 and the amount of material removed at the gauge pads 112may be determined.

Referring to FIGS. 6A and 6B, depicted are enlarged images of an examplecutting element 110 demonstrating surface area material loss, accordingto one or more embodiments. More specifically, FIG. 6A depicts thecutting element 110 with the digital plane 502 applied thereto andaligned with the cutting face, as generally described above. Thevolume/area calculation programming instruction may be programmed to usepredetermined presets to measure the distance from the digital plane 502to the actual scanned surfaces of the scanned file. The predeterminedpresets (e.g., alignment parameters) define at what depth to look forpoint clouds. This takes into account minor misalignments that can occuras well as spalling or thin layers of diamond loss. FIG. 6B depictspoint cloud data points 602 where the digital plane 502 aligns with thescanned file at the cutter table. Locations on the cutter face where nopoint cloud data points 602 are observed represent areas where thecutter table has eroded or worn away.

The volume/area calculation programming instruction may be programmed toquantify the area of the point cloud data points 602 and assign a valueto each cutting element 110. From that value, the volume/areacalculation programming instruction may be programmed to calculate theDAR for each cutting element 110 and may place all measurements intocomma separated variable (CSV) format as well as assign calculations inthe corresponding dialogue tree. Associating the DAR values with theindividual cutting elements 110 in the dialogue tree of the metrologysoftware helps facilitate viewing and/or reporting visual annotations ofthe DAR values on the model within subsequently-generated reports and/orthe software. As will be appreciated, similar calculations can beundertaken at the gauge pads 112 (FIGS. 1, 4, and 5B) using the digitalcylinder 504 to determine how much material was removed from the outerdiameter of the drill bit 100 during operation.

Referring again to FIG. 3, the method 300 may further include generatingone or more reports detailing quantified wear data, as at 322. Moreparticularly, the computer system 204 may be programmed to run a fourthor “auto-generate report” programming instruction, which may beprogrammed into the 3D modeling and metrology software. Theauto-generate report programming instruction may be configured togenerate a variety of types of reports. In some embodiments, theauto-generate report programming instruction may be programmed toproduce a PDF report with a corresponding data file containing imagesand tabular quantified wear data for each of the cutting elements 110(FIGS. 1, 4, and 6A-6B) listed in the data file for the drill bit 100.The PDF report may provide, among other features, color or “heat” mapsof the drill bit 100, which detail where erosion occurred and itsseverity. In such embodiments, a legend may be provided based onpre-determined tolerances of wear severity. Moreover, calculated valuesfor the cutting elements 110 may be placed in a table below each imagefor user reference.

The PDF report may further provide various images for each blade 104(FIG. 1) and key areas of interest on the drill bit 100. Morespecifically, the auto-generate report programming instruction may beconfigured to obtain and produce still images of each blade 104. In someembodiments, the PDF report may provide gauge diameter calculations,which provide measurements on how much material was lost at or near thegauge pads 112 (FIG. 1) of the drill bit 100.

FIGS. 7A-7D depict example wear data reports that may be generated usingthe auto-generate report programming instruction, according to one ormore embodiments. In FIG. 7A, unique annotations may be generated foreach cutting element to provide details of wear data; i.e., how muchmaterial loss occurred for each individual cutting element. In someembodiments, as illustrated, the severity of material loss may bereported graphically with a color-coded graphical output, wheredifferent colors correspond to differing amounts of material loss. Thereport in FIG. 7A also includes tabular quantified wear data for each ofthe cutting elements 110. This reporting helps the operator and toolcompany to visually correlate the tabular wear data to the physicallocation across the profile of the well tool to better understandpotential root causes of the wear.

In FIG. 7B, gauge diameter calculations for the drill bit 100 areprovided, which provide determinations on how much material was lost ator near the gauge pads 112 (FIG. 1) of the drill bit 100. Accordingly,this report aids in visual correlation of the gauge diameter and howthis measurement is being acquired.

FIG. 7C depicts a report that applies a color map overlay to images ofthe drill bit 100 as a visual representation of the wear and deviationsbeing reported on the drill bit 100. As indicated above, the severity ofmaterial loss may be reported graphically and color-coded, wheredifferent colors correspond to differing amounts of material loss. Thisvisual representation of material loss across the entire bit head can behelpful in evaluating hydraulic erosion trends to validate and/oroptimize CFD modeling as well as visualizing wear patterns as related toradial location on the bit.

FIG. 7D depicts an example CSV wear report that may be generatedfollowing the presently described automated inspection process,according to one or more embodiments. The CSV wear report output (orsimilar tabular report) may contain large amounts of data capturedduring the automated inspection process including bit description,application details, nominal area values, measured area values, diamondarea removed, gauge diameter, and tolerances, among many othervariables/metrics. At least one advantage to having detailed inspectiondata in a plain text CSV file format is that the user can easily importthe comprehensive dataset into many different applications and/ordatabases for storage and/or analysis.

Once wear data for the drill bit 100 is calculated and collected, it iscontemplated herein to optimize subsequent drill bit design and/ormanufacturing processes based on the wear data. More specifically, byknowing the drilling conditions the drill bit 100 undertook duringoperation and the resulting wear data, subsequent drill bits can bedesigned or manufactured to reinforce certain wear parts or regions ofthe bit to prolong its lifespan. Optimizing subsequent drill bit designand/or manufacturing, for instance, may entail a correlation analysis toidentify volume or rock removed, cut area, weight on bit, torque on bit,distance traveled, hydraulic energy, depth of cut, formation unconfinedcompressive strength, mechanical specific energy, and other operationparameters. Once the wear for a specific cutting element within thedrilling environment is determined, this can be used to optimize thedesign or cutter type for subsequent drill bits and thereby maximizeperformance when drilling in similar drilling environments and undersimilar drilling conditions.

In some embodiments, the methods described herein may include conductingan economic analysis of wear and/or wear rate for various material typesto determine association between cost and performance.

In some embodiments, the methods described herein may includecorrelating electronic drilling recorder (EDR) data to quantified weardata to determine depth of cut and/or energy applied to the well tool.In such embodiments, the EDR data may be compared to the wear data topotentially identify optimal parameters in order to mitigate (reduce)the wear. In some embodiments, this correlation process may allowoperators to determine wear rate per foot drilled. In at least oneembodiment, correlating the wear rate per foot drilled may take intoconsideration any forces acting on the individual wear parts of thedrill bit; e.g., weight on bit, torque on bit, hydraulic energy, RPM,etc. This analysis may be beneficial in helping to modify the design ofthe drill bit for improved performance and longevity, and/or optimizethe drilling parameters to maximize bit life.

In some embodiments, a wear index may be created and applied forspecific drilling applications and/or formations drilled using the drillbit 100, and thereby helping to predict wear probability. The wear indexcould be created once a large enough data set is obtained and correlatedto specific formation drilling applications. The wear index may beobtained or determined, at least in part, by using various statisticalanalysis and modeling methods, such as linear regression. In suchembodiments, coefficients and weights for various known downhole forcesmay be applied in the analysis and may be useful in predictive modelingthat can estimate wear given specific changes to the design and/ormaterials of the drill bit 100. In at least one embodiment, the wearindex could be on a scale of 1-10, but could alternatively be on adifferent type of scale, without departing from the scope of thedisclosure. In such embodiments, increments of the wear index may beequated to certain types of drill bits used in particular drillingapplications to maximize performance. Accordingly, the increments of thewear index may correspond to specific drilling applications and/orformations and may include correlation of rock strength analysis and/orunconfined compressive strength (UCS) with wear.

Sectioned Cutters

During the repair process of drill bits (e.g., PDC bits), worn cuttersare commonly detached from the cutter pocket and turned (rotated) toorient an unworn or new cutting edge toward the point of contact withthe underlying rock. In such processes, worn portion(s) of the cutterare turned (rotated) down into the cutter pocket in order to avoid beingdirectly exposed to contact with the rock being drilled. Some cuttersmay be turned (rotated) three or four times before scrapping the cutter,and each time the cutter is turned, an undamaged (sharp) cutter edge isexposed and aligned with the point of contact for a subsequent rundownhole. This process can save money by utilizing each cutter to itsmaximum potential.

Referring to FIG. 8, illustrated is an enlarged scanned view of a worncutter 110 seated within a corresponding cutter pocket 802. Asillustrated, the cutter 110 has a first worn edge 804 a and a secondworn edge 804 b, thus evidencing that the cutter 110 has been used in atleast two runs and detached and rotated within the cutter pocket 802, asgenerally described above. As a result, the first worn edge 804 a isoriented away from the point of contact with the rock and the secondworn edge 804 b is oriented toward the point of contact.

It may be desired to determine the wear and/or diamond area removed(DAR) from the cutting element 110 during the last operation (e.g., thelast run or trip downhole). To do this, an operator may follow the stepsof the method 300 of FIG. 3, but the resulting wear measurementsobtained using the method 300 would be skewed for the last run since itwould determine wear and/or DAR for both worn edges 804 a,b, whereas thewear and/or DAR for the second worn edge 804 b is only desired.

According to embodiments of the disclosure, the CAD file of the cuttingelement 110 may be digitally divided into two or more sections thatinclude corresponding two or more cutting edge portions of the cuttingelement 110 to be analyzed for wear. In the illustrated embodiment, thecutting element 110 is digitally divided into a first section 806 a anda second section 806 b, where the first section 806 a encompasses thefirst worn edge 804 a and the second section 806 b encompasses thesecond worn edge 804 b. The first section 806 a may be characterized asan “unexposed” section since the first worn edge 804 a is oriented awayfrom contact with the rock, whereas the second section 806 b may becharacterized as an “exposed section” since the second worn edge 804 ais oriented toward contact with the rock. In this embodiment, the firstand second sections 806 a,b comprise sections corresponding toapproximately 30% of the surface area of the cutter face 808. In otherembodiments, however, the sections 806 a,b may comprise other surfacearea percentages of the cutter face 808, such as up to 50% each. In yetother embodiments, the cutting element 110 may be digitally divided intomore than two sections, such as three or four sections. In embodimentswith four sections, the sections may each encompass 25% of the surfacearea of the cutter face 808, for example.

In this embodiment, step 320 of the method 300 of FIG. 3 may be modifiedand otherwise further include calculating the deviation between thesolid model file and the scanned file at an exposed section of thecutting element 110, such as the second section 806 b, whiledisregarding (ignoring) the unexposed section(s), such as the firstsection 806 a. As a result, the determination of material removed fromthe cutting element 110 will be isolated to only the second section 806b, which includes the second worn edge 804 b, while any wear present inthe first section 806 a, including the first worn edge 804 a, will beomitted from the resulting wear calculation. As will be appreciated,this will generate wear calculations for the cutting element 110corresponding to the most recent run, while omitting wear (losses) onthe cutting element 110 resulting from any prior runs, which would skewthe overall data.

Correlating Wear to Downhole Drilling Dynamics

It is contemplated herein to install various sensors in downhole welltools to obtain data related to the well tool during downhole operation,and correlate that data to subsequent observed wear. More particularly,one or more sensors may be installed in the drill bit 100 and designedto monitor (detect) various downhole drilling dynamics including, butnot limited to, vibration, acceleration, shock, orientation,temperature, weight on bit, pressure, or any combination thereof. Thisdata may be tracked to better understand the specific dynamicsexperienced by the drill bit 100 during operation.

However, such data may also be correlated to the wear experienced on thedrill bit 100 during operation to better understand the effect ofdrilling dysfunctions on cutter wear. This analysis may help an operatoroptimize drilling parameters, optimize parameter road mapping tomitigate tool dysfunction and wear, aid in bit and/or cutter design, andaid in material selection and optimization to mitigate tool dysfunctionand/or wear.

Automating the IADC Dull Grading System

As discussed herein, the International Association of Drill Contractors(IADC) developed and uses a dull bit grading system that provides astandardized protocol for evaluating drill bits and classifying drillbit wear/damage. In the IADC dull grading process, an evaluator visuallyinspects the dull bit and manually quantifies the observed wear using astandardized eight-field code; i.e., 0 to 8 scale, where 0=no wear, and8=effective cutting structure completely worn away. The current IADCdull grading system divides the bit into the inner ⅔ diameter of the bitbody and the outer ⅓ of the bit body and assigns an average of the wearsustained on the cutters located in the inner ⅔ and the outer ⅓ to the 0to 8 scale.

According to embodiments of the present disclosure, the basic evaluationprinciples provided by the IADC dull grading process may be automatedusing the methods described herein. In the presently disclosedembodiments, the computer system 204 may be programmed divide the bitbody 102 (FIG. 1) of the drill bit 100 (FIG. 1) into two or more radialsections extending radially outward from the centerline 108 (FIG. 1) ofthe bit body 102. In some embodiments, two radial sections may beidentified similar to the current IADC methodology, such as the inner ⅔diameter of the bit body 102 and the outer ⅓ of the bit body 102. Inother embodiments, however, other fractions of gauge diameter may beidentified extending from the centerline 108. In yet other embodiments,more than two radial sections extending from the centerline 108 may beidentified, without departing from the scope of the disclosure.

The average wear of the cutting elements 110 located within eachidentified radial section may then be determined in accordance with thewear calculation methods described herein, thus providing a percentdiamond area removed or “% DAR”. The % DAR for each identified radialsection may then be correlated with an industry standard dull gradingsystem, such as the IADC system or another system. In such embodiments,the % DAR for each identified radial section may be applied to the IADC0 to 8 scale and assigned a number between 0 and 8, depending on theresulting (calculated) % DAR. In other embodiments, however, the % DARmay be applied to any other grading scale system, without departing fromthe scope of the disclosure.

Failure Mode Classification

While understanding the amount of wear sustained is critical in welltool (e.g., drill bit) optimization, understanding the way the wear wasultimately sustained during operation may also be important. Byevaluating the characteristics of the wear, such as geometry, magnitude,direction, etc., it may be possible to classify the damage into specificfailure modes and thereby facilitate a root cause analysis of thedamage. Wear parts can fail due to a variety of root causes, forexample, such as abrasion, thermal degradation, mechanical overloading,erosion, corrosion, manufacturing defects, oxidation, or any combinationthereof.

FIG. 9A is an isometric view of an example cutting element 110 thatgraphically depicts sustained failure damage. More specifically, FIG. 9Adepicts a failure surface 902 indicating where a large portion of thecutting element 110 was extracted during operation by reason of failure.According to embodiments of the present disclosure, one or more digitalfeatures 904 may be generated to overlay the failure surface 902 andthereby generally follow the surface (contour) of the damage. Similar tothe digital features described above with reference to FIGS. 5A-5B, thedigital feature(s) 904 applied to the failure surface 902 may constitutecomputer-generated surfaces overlaid onto the scanned data of the welltool. Depending on the geometry of the resulting digital feature(s) 904,an appropriate failure mode may then be assigned to the worn part.Example failure modes include, but are not limited to, smooth wear,thermal-mechanical wear, cracking, chipping, spalling, tangentialfracture/break, delamination, etc.

The computer system 204 may also be programmed and otherwise trained touse machine learning and neural networks to aid in automated failureanalysis and classification for individual wear parts. Failure modeclassification could be achieved using various forms of artificialintelligence approaches. In example applications using machine or deeplearning, example images of common (or less-common) failure modes may beused to train an artificial intelligence model on how to classify thefailure modes accurately. In other applications, or in addition thereto,such as in rule-based artificial intelligence systems, thecharacteristics of the failure modes may be defined within coding inorder for the computer system 204 to properly assign a failureclassification.

In some embodiments, the resulting digital feature(s) 904 applied to thefailure surface may then be compared to the CAD model of the wear partin order to model the missing portion of the wear part. FIG. 9B, forexample, shows a graphical representation 906 of the missing part(material) from the cutting element 110 of FIG. 9A. The graphicalrepresentation 906 may prove advantageous in helping to determine thegeometry and amount (volume) of material lost from the cutting element110.

Computational Fluid Dynamics

Upon calculating deviation between the solid model file and the scannedfile at the digital features for the wear parts, and determiningmaterial removed from the wear parts of the well tool, it is alsocontemplated herein to compare (correlate) the determined wear data tocomputational fluid dynamics (CFD) modeling. Correlating wear to CFDresults, in this instance flow lines, enables an operator (user) toconfirm if the damage being sustained is related in some way to drillingfluid circulation, which may result in erosion and/or corrosion. In someembodiments, the CFD modeling may be generated from an add-in within CADmodeling/design software packages (e.g., SolidWorks).

CFD simulations can have a multitude of variables and/or parameters thatan operator (user) can adjust to best fit the real world scenario orapplication. It is often difficult to determine the accuracy of thesimulations, thereby leaving much room for ambiguity in selecting themost appropriate parameters to use during simulations. Having highlyprecise wear quantification, however, provides a much needed feedbacksystem for the CFD analysts to evaluate (or validate) the accuracy oftheir simulations and adjust the parameters of the models as needed tobetter match the actual or observed effects of fluids on the well tool.Accordingly, comparing the wear data to CFD modeling may proveadvantageous in helping to validate CFD modeling.

FIG. 10 depicts an example of observed CFD flow lines across a well tool(e.g., the drill bit 100) being correlated to cutting element wear,according to one or more embodiments. In the illustrated example, flowlines are observed traveling (flowing) across erosion-prone (relative tothe diamond table) cutting element substrates on the CFD modeling, and acorresponding spike in % DAR is recorded in the adjoining graph. If theerosion-prone substrate sustains erosion, the diamond table of thecutting element may be left unsupported and is more likely to fail. Withthis understanding (data), an operator (user, designer, manufacture,etc.) may be able to adjust one or more parameters of the drill bit 100to help prevent erosion. In some embodiments, for instance, theorientation of nozzles 1002 in the drill bit 100 may be adjusted toreduce the hydraulic flow traveling across the cutting elements, whichmay reduce the risk of fluid-related damage on the cutting elements.FIG. 10 provides an example of this relationship and phenomenon.Accordingly, in some embodiments, wear patterns identified on the drillbit 100 may be correlated to CFD modeling to optimize hydraulic layoutsof the drill bit 100 and thereby minimize fluid erosion.

FIG. 11 is a schematic diagram of the computer system 204 of FIG. 1. Asshown, the computer system 204 includes one or more processors 1102,which can control the operation of the computer system 204. “Processors”are also referred to herein as “controllers.” The processor(s) 1102 caninclude any type of microprocessor or central processing unit (CPU),including programmable general-purpose or special-purposemicroprocessors and/or any one of a variety of proprietary orcommercially available single or multi-processor systems. The computersystem 204 can also include one or more memories 1104, which can providetemporary storage for code to be executed by the processor(s) 1102 orfor data acquired from one or more users, storage devices, and/ordatabases. The memory 1104 can include read-only memory (ROM), flashmemory, one or more varieties of random access memory (RAM) (e.g.,static RAM (SRAM), dynamic RAM (DRAM), or synchronous DRAM (SDRAM)),and/or a combination of memory technologies.

The various elements of the computer system 204 can be coupled to a bussystem 1106. The illustrated bus system 1106 is an abstraction thatrepresents any one or more separate physical busses, communicationlines/interfaces, and/or multi-drop or point-to-point connections,connected by appropriate bridges, adapters, and/or controllers. Thecomputer system 204 can also include one or more network interface(s)1108, one or more input/output (IO) interface(s) 1110, and the one ormore storage device(s) 812.

The network interface(s) 1108 can enable the computer system 204 tocommunicate with remote devices, e.g., other computer systems, over anetwork, and can be, for non-limiting example, remote desktop connectioninterfaces, Ethernet adapters, and/or other local area network (LAN)adapters. The IO interface(s) 1110 can include one or more interfacecomponents to connect the computer system 204 with other electronicequipment. For non-limiting example, the IO interface(s) 1110 caninclude high-speed data ports, such as universal serial bus (USB) ports,1394 ports, Wi-Fi, Bluetooth, etc. Additionally, the computer system 204can be accessible to a human user, and thus the IO interface(s) 1110 caninclude displays, speakers, keyboards, pointing devices, and/or variousother video, audio, or alphanumeric interfaces.

The storage device(s) 1112 can include any conventional medium forstoring data in a non-volatile and/or non-transient manner. In someaspects, the storage device(s) 1112 may be the same as the storagedevice 138 of FIG. 1. The storage device(s) 1112 can hold data and/orinstructions in a persistent state, i.e., the value(s) are retaineddespite interruption of power to the computer system 204. In at leastone aspect, the database 136 of FIG. 1 may be located on the storagedevice(s) 1112. The storage device(s) 1112 can include one or more harddisk drives, flash drives, USB drives, optical drives, various mediacards, diskettes, compact discs, and/or any combination thereof and canbe directly connected to the computer system(s) 204 or remotelyconnected thereto, such as over a network. In an exemplary embodiment,the storage device(s) 1112 can include a tangible or non-transitorycomputer readable medium configured to store data, e.g., a hard diskdrive, a flash drive, a USB drive, an optical drive, a media card, adiskette, a compact disc, etc.

The elements illustrated in FIG. 8 can be some or all of the elements ofa single physical machine. In other embodiments, however, and asmentioned above, the computer system 204 may alternatively include twoor more computers or physical computing machines networked together orotherwise capable of communicating one with the other to achieve acommon goal. In addition, not all of the illustrated elements need to belocated on or in the same physical machine. Exemplary computer systemsinclude conventional desktop computers, workstations, minicomputers,laptop computers, tablet computers, personal digital assistants (PDAs),and mobile phones, and the like.

The computer system 204 can include a web browser for retrieving webpages or other markup language streams, presenting those pages and/orstreams (visually, aurally, or otherwise), executing scripts, controlsand other code on those pages/streams, accepting user input with respectto those pages/streams (e.g., for purposes of completing input fields),issuing HyperText Transfer Protocol (HTTP) requests with respect tothose pages/streams or otherwise (e.g., for submitting to a serverinformation from the completed input fields), and so forth. The webpages or other markup language can be in HyperText Markup Language(HTML) or other conventional forms, including embedded Extensible MarkupLanguage (XML), scripts, controls, and so forth. The computer system 204can also include a web server for generating and/or delivering the webpages to client computer systems.

In an exemplary embodiment, the computer system 204 can be provided as asingle unit, e.g., as a single server, as a single tower, containedwithin a single housing, etc. The single unit can be modular such thatvarious aspects thereof can be swapped in and out as needed for, e.g.,upgrade, replacement, maintenance, etc., without interruptingfunctionality of any other aspects of the system. The single unit canthus also be scalable with the ability to be added to as additionalmodules and/or additional functionality of existing modules are desiredand/or improved upon.

The computer system 204 can also include any of a variety of othersoftware and/or hardware components, including by way of non-limitingexample, operating systems and database management systems. Although anexemplary computer system is depicted and described herein, it will beappreciated that this is for the sake of generality and convenience. Inother embodiments, the computer system may differ in architecture andoperation from that shown and described here.

Embodiments disclosed herein include:

A. A method of quantifying wear data on a well tool includes identifyingthe well tool based on a solid model file and a data file correspondingto the well tool, wherein the solid model and data files are stored on acomputer system and separately identify wear parts of the well tool,scanning the well tool with a scanner and thereby generating a scannedfile of the well tool, the scanner being in communication with thecomputer system, aligning the scanned file with the solid model file toobtain an overlay output, creating digital features on the wear parts ofthe scanned file, and calculating deviation between the solid model fileand the scanned file at the digital features for the wear parts andthereby determining material removed from the wear parts of the welltool.

Embodiment A may have one or more of the following additional elementsin any combination: Element 1: wherein the solid model file and the datafile comprise design and preparation files corresponding to the welltool, and wherein data in the solid model file and the data file areseparable into the wear parts of the well tool. Element 2: whereinidentifying the well tool further comprises inputting into the computersystem tool data corresponding to the well tool, the tool data includingpart number, serial number, and operation information for the well tool.Element 3: wherein scanning the well tool is preceded by situating thewell tool in a predetermined alignment. Element 4: wherein aligning thescanned file with the solid model file comprises undertaking a manualpoint pair alignment between the scanned file and the solid model file.Element 5: wherein undertaking the manual point pair alignment comprisesmarking one or more surfaces in the solid model file with uniqueidentifiers, and marking one or more of the surfaces in the scanned filewith corresponding unique identifiers and thereby linking the solidmodel file to the scanned file. Element 6: wherein aligning the scannedfile with the solid model file comprises globally aligning the scannedfile with the solid model file by creating a best-fit global alignmentbetween all surfaces of the scanned mesh and solid model files. Element7: further comprising performing a local alignment of individual wearparts of the well tool. Element 8: wherein the well tool is a drill bithaving a plurality of cutting elements fixed to blades, and whereincreating the digital features on the wear parts of the scanned filecomprises generating and aligning a digital plane with a cutter face ofeach cutting element. Element 9: wherein calculating the deviationbetween the solid model file and the scanned file comprises retrievingnominal values set for a cutter dimension of each cutting element, andcomparing the nominal values to the scanned file at the digital planesand thereby quantifying diamond area removed from each cutting element.Element 10: wherein the drill bit further includes gauge pads andcreating the digital features on the wear parts of the scanned filefurther comprises generating and aligning a digital cylinder with thegauge pads. Element 11: wherein calculating the deviation between thesolid model file and the scanned file comprises retrieving nominalvalues set for an outer diameter of the drill bit at the gauge pads, andcomparing the nominal values to the scanned file at the digital cylinderand thereby quantifying an amount of material removed at the gauge padsor determining if the gauge pads are out of tolerance. Element 12:further comprising generating one or more reports detailing quantifiedwear data for each wear part of the well tool. Element 13: wherein thewell tool comprises a drill bit, the method further comprisingcorrelating the material removed from the wear parts to performance andthereby producing wear or wear rate per foot drilled. Element 14:further comprising correlating the wear with forces acting on the wearparts of the drill bit, and modifying a design of the drill bit based oncorrelation of the wear with the forces acting on the wear parts.Element 15: further comprising creating and applying a wear index forspecific drilling applications and formations drilled and therebypredicting wear probability. Element 16: wherein the well tool comprisesa drill bit and the wear parts include a cutting element secured to thedrill bit, and wherein calculating the deviation between the solid modelfile and the scanned file comprises dividing the solid model file of thecutting element into two or more sections that include corresponding twoor more cutting edge portions to be analyzed for wear, wherein one ofthe two or more sections is an exposed section while remaining sectionsof the two or more sections are unexposed sections, calculating thedeviation between the solid model file at the exposed section and thescanned file, and disregarding deviation between the solid model file atthe unexposed section and the scanned file. Element 17: wherein the welltool comprises a drill bit with a bit body having a centerline, andwherein the method further comprises dividing the bit body into two ormore radial sections extending radially outward from the centerline,calculating an average wear of cutting elements located within eachradial section and thereby determining a percent diamond area removed (%DAR) for each radial section, and correlating the % DAR for each radialsection with an industry standard dull grading system. Element 18:further comprising comparing the material removed from the wear parts tocomputational fluid dynamics (CFD) modeling results of the well tool,correlating the CFD modeling results to the material removed, andadjusting one or more parameters of the well tool to prevent erosionbased on the CFD modeling results and the material removed. Element 19:wherein creating the digital features on the wear parts of the scannedfile comprise overlaying a failure surface on one of the wear parts witha plurality of computer-generated digital features, and assigning afailure mode to the failure surface based on a geometry of the pluralityof computer-generated digital features. Element 20: further comprisingcalculating deviation between the solid model file and the scanned fileat the failure surface of the one of the wear parts, and graphicallymodeling an amount removed from the one of the wear parts based on theplurality of computer-generated digital features. Element 21: whereinassigning the failure mode to the failure surface comprises training thecomputer system with a plurality of known failure mode images, andclassifying the failure mode with the computer system based on theplurality of known failure mode images. Element 22: wherein the welltool comprises oilfield equipment selected from the group consisting ofa rotary drill bit, a bit body associated with a rotary drill bit, afixed cutter drill bit, a drill string stabilizer, a roller cone drillbit, a cone for a roller cone drill bit, a rotary steering tool, alogging while drilling tool, a measurement while drilling tool, a sidewall coring tool, an underreamer, a fishing spear, a washover tool, awhipstock, a production packer component, float equipment, a casingshoe, a well screen, a gas lift mandrel, a downhole tractor, a tooljoint, a rotor for a downhole motor, a stator for a downhole motor, ablades for a downhole turbine, a latch for a downhole tool, and anycombination thereof.

By way of non-limiting example, exemplary combinations applicable toembodiment A include: Element 4 with Element 5; Element 6 with Element7; Element 8 with Element 9; Element 9 with Element 10; Element 10 withElement 11; Element 13 with Element 14; Element 13 with Element 15;Element 19 with Element 20; and Element 19 with Element 21.

Therefore, the disclosed systems and methods are well adapted to attainthe ends and advantages mentioned as well as those that are inherenttherein. The particular embodiments disclosed above are illustrativeonly, as the teachings of the present disclosure may be modified andpracticed in different but equivalent manners apparent to those skilledin the art having the benefit of the teachings herein. Furthermore, nolimitations are intended to the details of construction or design hereinshown, other than as described in the claims below. It is thereforeevident that the particular illustrative embodiments disclosed above maybe altered, combined, or modified and all such variations are consideredwithin the scope of the present disclosure. The systems and methodsillustratively disclosed herein may suitably be practiced in the absenceof any element that is not specifically disclosed herein and/or anyoptional element disclosed herein. While compositions and methods aredescribed in terms of “comprising,” “containing,” or “including” variouscomponents or steps, the compositions and methods can also “consistessentially of” or “consist of” the various components and steps. Allnumbers and ranges disclosed above may vary by some amount. Whenever anumerical range with a lower limit and an upper limit is disclosed, anynumber and any included range falling within the range is specificallydisclosed. In particular, every range of values (of the form, “fromabout a to about b,” or, equivalently, “from approximately a to b,” or,equivalently, “from approximately a-b”) disclosed herein is to beunderstood to set forth every number and range encompassed within thebroader range of values. Also, the terms in the claims have their plain,ordinary meaning unless otherwise explicitly and clearly defined by thepatentee. Moreover, the indefinite articles “a” or “an,” as used in theclaims, are defined herein to mean one or more than one of the elementsthat it introduces. If there is any conflict in the usages of a word orterm in this specification and one or more patent or other documentsthat may be incorporated herein by reference, the definitions that areconsistent with this specification should be adopted.

As used herein, the phrase “at least one of” preceding a series ofitems, with the terms “and” or “or” to separate any of the items,modifies the list as a whole, rather than each member of the list (i.e.,each item). The phrase “at least one of” allows a meaning that includesat least one of any one of the items, and/or at least one of anycombination of the items, and/or at least one of each of the items. Byway of example, the phrases “at least one of A, B, and C” or “at leastone of A, B, or C” each refer to only A, only B, or only C; anycombination of A, B, and C; and/or at least one of each of A, B, and C.

1. A method of quantifying wear data on a well tool, comprising:identifying the well tool based on a solid model file and a data filecorresponding to the well tool, wherein the solid model and data filesare stored on a computer system and separately identify wear parts ofthe well tool; scanning the well tool with a scanner and therebygenerating a scanned file of the well tool, the scanner being incommunication with the computer system; aligning the scanned file withthe solid model file to obtain an overlay output; creating digitalfeatures on the wear parts of the scanned file; and calculatingdeviation between the solid model file and the scanned file at thedigital features for the wear parts and thereby determining materialremoved from the wear parts of the well tool.
 2. The method of claim 1,wherein the solid model file and the data file comprise design andpreparation files corresponding to the well tool, and wherein data inthe solid model file and the data file are separable into the wear partsof the well tool.
 3. The method of claim 1, wherein identifying the welltool further comprises inputting into the computer system tool datacorresponding to the well tool, the tool data including part number,serial number, and operation information for the well tool.
 4. Themethod of claim 1, wherein scanning the well tool is preceded bysituating the well tool in a predetermined alignment.
 5. The method ofclaim 1, wherein aligning the scanned file with the solid model filecomprises undertaking a manual point pair alignment between the scannedfile and the solid model file.
 6. The method of claim 5, whereinundertaking the manual point pair alignment comprises: marking one ormore surfaces in the solid model file with unique identifiers; andmarking one or more of the surfaces in the scanned file withcorresponding unique identifiers and thereby linking the solid modelfile to the scanned file.
 7. The method of claim 1, wherein aligning thescanned file with the solid model file comprises globally aligning thescanned file with the solid model file by creating a best-fit globalalignment between all surfaces of the scanned mesh and solid modelfiles.
 8. The method of claim 7, further comprising performing a localalignment of individual wear parts of the well tool.
 9. The method ofclaim 1, wherein the well tool is a drill bit having a plurality ofcutting elements fixed to blades, and wherein creating the digitalfeatures on the wear parts of the scanned file comprises generating andaligning a digital plane with a cutter face of each cutting element. 10.The method of claim 9, wherein calculating the deviation between thesolid model file and the scanned file comprises: retrieving nominalvalues set for a cutter dimension of each cutting element; and comparingthe nominal values to the scanned file at the digital planes and therebyquantifying diamond area removed from each cutting element.
 11. Themethod of claim 9, wherein the drill bit further includes gauge pads andcreating the digital features on the wear parts of the scanned filefurther comprises generating and aligning a digital cylinder with thegauge pads.
 12. The method of claim 11, wherein calculating thedeviation between the solid model file and the scanned file comprises:retrieving nominal values set for an outer diameter of the drill bit atthe gauge pads; and comparing the nominal values to the scanned file atthe digital cylinder and thereby quantifying an amount of materialremoved at the gauge pads or determining if the gauge pads are out oftolerance.
 13. The method of claim 1, further comprising generating oneor more reports detailing quantified wear data for each wear part of thewell tool.
 14. The method of claim 1, wherein the well tool comprises adrill bit, the method further comprising correlating the materialremoved from the wear parts to performance and thereby producing wear orwear rate per foot drilled.
 15. The method of claim 14, furthercomprising: correlating the wear with forces acting on the wear parts ofthe drill bit; and modifying a design of the drill bit based oncorrelation of the wear with the forces acting on the wear parts. 16.The method of claim 14, further comprising creating and applying a wearindex for specific drilling applications and formations drilled andthereby predicting wear probability.
 17. The method of claim 1, whereinthe well tool comprises a drill bit and the wear parts include a cuttingelement secured to the drill bit, and wherein calculating the deviationbetween the solid model file and the scanned file comprises: dividingthe solid model file of the cutting element into two or more sectionsthat include corresponding two or more cutting edge portions to beanalyzed for wear, wherein one of the two or more sections is an exposedsection while remaining sections of the two or more sections areunexposed sections; calculating the deviation between the solid modelfile at the exposed section and the scanned file; and disregardingdeviation between the solid model file at the unexposed section and thescanned file.
 18. The method of claim 1, wherein the well tool comprisesa drill bit with a bit body having a centerline, and wherein the methodfurther comprises: dividing the bit body into two or more radialsections extending radially outward from the centerline; calculating anaverage wear of cutting elements located within each radial section andthereby determining a percent diamond area removed (% DAR) for eachradial section; and correlating the % DAR for each radial section withan industry standard dull grading system.
 19. The method of claim 1,further comprising: comparing the material removed from the wear partsto computational fluid dynamics (CFD) modeling results of the well tool;correlating the CFD modeling results to the material removed; andadjusting one or more parameters of the well tool to prevent erosionbased on the CFD modeling results and the material removed.
 20. Themethod of claim 1, wherein creating the digital features on the wearparts of the scanned file comprise: overlaying a failure surface on oneof the wear parts with a plurality of computer-generated digitalfeatures; and assigning a failure mode to the failure surface based on ageometry of the plurality of computer-generated digital features. 21.The method of claim 20, further comprising: calculating deviationbetween the solid model file and the scanned file at the failure surfaceof the one of the wear parts; and graphically modeling an amount removedfrom the one of the wear parts based on the plurality ofcomputer-generated digital features.
 22. The method of claim 20, whereinassigning the failure mode to the failure surface comprises: trainingthe computer system with a plurality of known failure mode images; andclassifying the failure mode with the computer system based on theplurality of known failure mode images.
 23. The method of claim 1,wherein the well tool comprises oilfield equipment selected from thegroup consisting of a rotary drill bit, a bit body associated with arotary drill bit, a fixed cutter drill bit, a drill string stabilizer, aroller cone drill bit, a cone for a roller cone drill bit, a rotarysteering tool, a logging while drilling tool, a measurement whiledrilling tool, a side wall coring tool, an underreamer, a fishing spear,a washover tool, a whipstock, a production packer component, floatequipment, a casing shoe, a well screen, a gas lift mandrel, a downholetractor, a tool joint, a rotor for a downhole motor, a stator for adownhole motor, a blades for a downhole turbine, a latch for a downholetool, and any combination thereof.
 24. (canceled)